U.S. patent number 11,029,246 [Application Number 17/110,717] was granted by the patent office on 2021-06-08 for colorimetric detection of shale inhibitors and/or salts.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. The grantee listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Dale E. Jamison, Xiangnan Ye.
United States Patent |
11,029,246 |
Jamison , et al. |
June 8, 2021 |
Colorimetric detection of shale inhibitors and/or salts
Abstract
A method of detecting a shale inhibitor and/or a salt content in
a wellbore servicing fluid (WSF), the method comprising determining
a water salinity of a wellbore servicing fluid; dosing a known
volume of the wellbore servicing fluid into a container; optionally
adding a known volume of diluent (e.g., water) and mixing to
provide a test sample; combining the test sample with a chromophore
specific to the shale inhibitor and/or the salt, respectively, and
optionally mixing; measuring the shale inhibitor content and/or the
salt content, respectively, of the test sample using colorimetry;
reporting the data from the measuring to a computer control system;
determining a wellbore servicing fluid treatment based on the
measured shale inhibitor content and/or salt content; subjecting
the wellbore servicing fluid system to the treatment; and
optionally waiting for a waiting time to retest the wellbore
servicing fluid system and repeating.
Inventors: |
Jamison; Dale E. (Humble,
TX), Ye; Xiangnan (Cypress, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc. (Houston, TX)
|
Family
ID: |
1000005300651 |
Appl.
No.: |
17/110,717 |
Filed: |
December 3, 2020 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
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62992619 |
Mar 20, 2020 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G01N
31/22 (20130101); G01N 33/2823 (20130101); G01N
21/25 (20130101); G01N 1/38 (20130101) |
Current International
Class: |
G01N
21/25 (20060101); G01N 31/22 (20060101); G01N
33/28 (20060101); G01N 1/38 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
Hang, Pham Thi et al., "Methylene Blue Absorption by Clay Minerals.
Determination of Surface Areas and Cation Exchange Capacities
(Clay-Organic Studies XVIII," Clays and Clay Minerals, 1970, pp.
203-212, vol. 18, Pergamon Dress. cited by applicant .
Kostesha, N.V. et al., "Development of the colorimetric sensor
array for detection of explosives and volatile organic compounds in
air," Technical University of Denmark, 9 pages. cited by applicant
.
Filing Receipt, Specification and Drawings for U.S. Appl. No.
62/992,619, entitled "Colorimetric Detection of Shale Inhibitors
and/or Salts," filed Mar. 20, 2020, 40 pages. cited by applicant
.
Foreign Communication of Related Application--International Search
Report and Written Opinion of the International Searching
Authority, International Application No. PCT/US2020/063898, dated
Mar. 16, 2021, 11 pages. cited by applicant.
|
Primary Examiner: Ahmed; Jamil
Attorney, Agent or Firm: Conley Rose, P.C. Carroll; Rodney
B.
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATIONS
This application claims priority under 35 U.S.C. .sctn. 119(e) to
U.S. Provisional Patent Application No. 62/992,619 filed on Mar.
20, 2020 and entitled "Colorimetric Detection of Shale Inhibitors
and/or Salts," the disclosure of which is hereby incorporated
herein by reference in its entirety.
Claims
What is claimed is:
1. A method of detecting a salt content of a wellbore servicing
fluid (WSF) of a wellbore servicing fluid system as described
herein, the method comprising: (a) determining a water salinity of
a wellbore servicing fluid; (b) dosing an aliquot of the wellbore
servicing fluid into a container; (c) combining the aliquot of the
wellbore servicing fluid with a detector compound specific to the
salt and mixing to provide a detection solution in the container,
wherein the detection solution is characterized by at least one
absorption peak wavelength in the range of from about 380
nanometers (nm) to about 760 nm; (d) measuring the salt content of
the detection solution using colorimetry by detecting an absorption
intensity for the detection solution at a wavelength within about
.+-.20% of the at least one absorption peak wavelength, comparing
the absorption intensity of the detection solution at the
wavelength within about .+-.20% of the at least one absorption peak
wavelength with a target absorption intensity to determine the
amount of salt in the WSF, and comparing the amount of salt in the
WSF with a target amount of the salt; (e) reporting the data from
the measuring at (d) to a computer control system; (f) determining
a wellbore servicing fluid treatment based on the salt content
and/or a content of shale inhibitors; and (g) subjecting the
wellbore servicing fluid of the wellbore servicing fluid system to
the treatment.
2. The method of claim 1 further comprising: adding a known volume
of diluent and mixing prior to (c); and/or (h) waiting for a
waiting time to retest the wellbore servicing fluid system; and (i)
repeating steps (a) through (g) after the waiting time.
3. The method of claim 1, wherein the wellbore servicing fluid
comprises a drilling fluid.
4. The method of claim 3, wherein the drilling fluid has been
recovered from circulation downhole.
5. The method of claim 3, wherein the wellbore servicing fluid
comprises a water based mud (WBM).
6. The method of claim 3, wherein the wellbore servicing fluid
comprises an oil based mud (OBM), and wherein dosing at (b) further
comprises separating an aqueous phase from an oil phase, and
wherein the aliquot comprises at least a portion of the separated
aqueous phase.
7. The method of claim 1, wherein (d) measuring the salt content
using colorimetry at (e) comprises utilizing an analyzer comprising
photosensitive dye(s) comprising the chromophore specific to the
salt.
8. The method of claim 1, wherein the salt comprises NaCl, KCl,
NaBr, CaCl.sub.2, CaBr.sub.2, MgCl.sub.2, MgBr.sub.2, ZnBr.sub.2,
an acetate salt, sodium acetate, potassium acetate, ammonium
chloride (NH.sub.4Cl), potassium phosphate, sodium formate,
potassium formate, cesium formate, or a combination thereof.
9. The method of claim 8, wherein the wellbore servicing fluid
comprises a brine.
10. The method of claim 1, wherein the aliquot of the wellbore
servicing fluid comprises a solids reduced and/or diluted volume of
the wellbore servicing fluid.
11. A method of detecting a shale inhibitor content of a wellbore
servicing fluid (WSF) of a wellbore servicing fluid system as
described herein, the method comprising: (a) determining a water
phase salinity (WPS) of a wellbore servicing fluid; (b) dosing an
aliquot of the wellbore servicing fluid into a container; (c)
combining the aliquot of the wellbore servicing fluid with a
detector compound specific to the shale inhibitor and mixing to
provide a detection solution in the container, wherein the
detection solution is characterized by at least one absorption peak
wavelength in the range of from about 380 nanometers (nm) to about
760 nm; (d) measuring the shale inhibitor content of the detection
solution using colorimetry by detecting an absorption intensity for
the detection solution at a wavelength within about .+-.20% of the
at least one absorption peak wavelength, comparing the absorption
intensity of the detection solution at the wavelength within about
.+-.20% of the at least one absorption peak wavelength with a
target absorption intensity to determine the amount of shale
inhibitor in the WSF, and comparing the amount of shale inhibitor
in the WSF with a target amount of the shale inhibitor; (e)
reporting the data from the measuring at (d) to a computer control
system; (f) determining a wellbore servicing fluid treatment based
on the water phase salinity (WPS) from (a) and the content of shale
inhibitor from (d); and (g) subjecting the wellbore servicing fluid
of the wellbore servicing fluid system to the treatment.
12. The method of claim 11 further comprising: adding a known
volume of diluent and mixing prior to (c); and/or (h) waiting for a
waiting time to retest the wellbore servicing fluid system; and (i)
repeating steps (a) through (g) after the waiting time.
13. The method of claim 11, wherein the wellbore servicing fluid
comprises a drilling fluid.
14. The method of claim 13, wherein the drilling fluid has been
recovered from circulation downhole.
15. The method of claim 13, wherein the wellbore servicing fluid
comprises a water based mud (WBM).
16. The method of claim 13, wherein the wellbore servicing fluid
comprises an oil based mud (OBM), and wherein dosing at (b) further
comprises separating an aqueous phase from an oil phase, and
wherein the aliquot comprises at least a portion of the separated
aqueous phase.
17. The method of claim 11, wherein (d) measuring the shale
inhibitor content of the detection solution using colorimetry at
(d) comprises utilizing an analyzer comprising photosensitive
dye(s) comprising the chromophore specific to the shale
inhibitor.
18. The method of claim 11, wherein the shale inhibitor comprises a
polymer, a charged polymer, a salt, or a combination thereof.
19. The method of claim 18, wherein the shale inhibitor comprises a
high molecular weight polymer, potassium chloride, sodium chloride,
or a combination thereof.
20. The method of claim 11, wherein the aliquot of the wellbore
servicing fluid comprises a solids reduced and/or diluted volume of
the wellbore servicing fluid.
Description
BACKGROUND
This disclosure relates to methods of servicing a wellbore. More
specifically, it relates to methods of detecting shale inhibitors
and/or salts in wellbore servicing fluids.
Natural resources such as gas, oil, and water residing in a
subterranean formation or zone are usually recovered by drilling a
wellbore down to the subterranean formation while circulating a
drilling fluid in the wellbore. After terminating the circulation
of the drilling fluid, a string of pipe, e.g., casing, is run in
the wellbore. The drilling fluid is then usually circulated
downward through the interior of the pipe and upward through the
annulus, which is located between the exterior of the pipe and the
walls of the wellbore. Shale inhibitors and salts are ubiquitous
components in drilling fluids. Shale inhibitors and/or salts can
have predetermined concentrations in drilling fluids to prevent
problems during the drilling process, such as viscosity build-up,
bit balling, wellbore caving and ballooning, etc. However, during
the drilling process, shale inhibitors and/or salts can be lost to
or gained from the formation. The inability to accurately identify
the active concentration of shale inhibitors and/or salts in
drilling fluids in real-time can result in economic losses (e.g.,
increased incidence of non-productive time). Thus, an ongoing need
exists for real-time quantitative detection of shale inhibitors
and/or salts in wellbore servicing fluids, such as drilling
fluids.
The foregoing has outlined rather broadly the features and
technical advantages of the present invention in order that the
detailed description of the invention that follows may be better
understood. Additional features and advantages of the invention
will be described hereinafter that form the subject of the claims
of the invention. It should be appreciated by those skilled in the
art that the conception and the specific embodiments disclosed may
be readily utilized as a basis for modifying or designing other
structures for carrying out the same purposes of the present
invention. It should also be realized by those skilled in the art
that such equivalent constructions do not depart from the spirit
and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding of the present disclosure and the
advantages thereof, reference is now made to the following brief
description, taken in connection with the accompanying drawings and
detailed description, wherein like reference numerals represent
like parts.
FIG. 1 is a flow chart showing a representative method for
measuring a salt content in a wellbore servicing fluid according to
this disclosure.
FIG. 2 is a flow chart showing a representative method for
measuring a shale inhibitor content in a wellbore servicing fluid
according to this disclosure.
DETAILED DESCRIPTION
It should be understood at the outset that although an illustrative
implementation of one or more embodiments are provided below, the
disclosed systems and/or methods may be implemented using any
number of techniques, whether currently known or in existence. The
disclosure should in no way be limited to the illustrative
implementations, drawings, and techniques below, including the
exemplary designs and implementations illustrated and described
herein, but may be modified within the scope of the appended claims
along with their full scope of equivalents.
Disclosed herein are methods of detecting shale inhibitors and/or
salts in wellbore servicing fluids or compositions (collectively
referred to herein as WSFs). The amount (e.g., concentration) of
shale inhibitors and/or salts can be determined by reacting the
shale inhibitors and/or salts with a detector compound, which may
result in highly conjugated molecules that display color (e.g.,
visual color); wherein such highly conjugated molecules can absorb
light in the ultraviolet-visible (UV-VIS) range and/or in the
visible (VIS) range; and wherein the absorption intensity can be
used to derive the amount of the shale inhibitors and/or salts in
the WSF. Although described hereinbelow with reference to
absorbance, in aspects light reflectance can be utilized.
In an aspect, a method of detecting a shale inhibitor and/or a salt
in a WSF can include (a) contacting an aliquot of the WSF with a
detector compound to form a detection solution; wherein the WSF
includes the shale inhibitor and/or the salt; and wherein the
detection solution is characterized by at least one absorption peak
wavelength in the range of from about 380 nanometers (nm) to about
760 nm; (b) detecting an absorption intensity for the detection
solution at a wavelength within about .+-.20% of the at least one
absorption peak wavelength; (c) comparing the absorption intensity
of the detection solution at the wavelength within about .+-.20% of
the at least one absorption peak wavelength with a target
absorption intensity of the shale inhibitor and/or the salt to
determine the amount of the shale inhibitor and/or the salt in the
WSF; and (d) comparing the amount of the shale inhibitor and/or
salt in the WSF with a target amount of the shale inhibitor and/or
the salt. The detection solution can be characterized by a visible
color. In some aspects, the aliquot of the WSF can be further
characterized by a visible color, wherein the visible color and/or
color intensity of the detection solution is different from the
visible color and/or color intensity of the aliquot of the WSF. In
other aspects, the aliquot of the WSF can be colorless, for example
the aliquot of the WSF can be a clear liquid.
Further disclosed herein are methods of servicing a wellbore in a
subterranean formation including the real-time detection of shale
inhibitors and/or salts in WSF used in the wellbore and/or
subterranean formation.
In an aspect, a method of servicing a wellbore in a subterranean
formation can include preparing a WSF including a base fluid and a
shale inhibitor and/or salt, wherein the shale inhibitor and/or
salt is present in the WSF in a target amount. The target amount
can be greater than or equal to zero. For example, the target
amount of the salt may be zero, in aspects.
In an aspect, the WSF suitable for use in the present disclosure
may include any suitable WSF. As used herein, a "servicing fluid"
or "treatment fluid" refers generally to any fluid that may be used
in a subterranean application in conjunction with a desired
function and/or for a desired purpose, including but not limited to
fluids used to drill, complete, work over, fracture, repair, clean,
or in any way prepare a wellbore for the recovery of materials
residing in a subterranean formation penetrated by the wellbore.
The servicing fluid is for use in a wellbore that penetrates a
subterranean formation. It is to be understood that "subterranean
formation" encompasses both areas below exposed earth and areas
below earth covered by water such as ocean or fresh water. In an
aspect, the WSF (e.g., including a base fluid, a shale inhibitor
and/or a salt) as disclosed herein can be a drilling fluid or a
completion fluid. In an aspect, the WSF as disclosed herein can be
a drilling fluid.
In an aspect, the WSF includes a base fluid. In some aspects, the
base fluid is an aqueous fluid. In other aspects, the base fluid
includes an emulsion.
The salt detected via this disclosure can have monovalent and/or
polyvalent cations, alkali and alkaline earth metals, or
combinations thereof. Additional examples of suitable salts include
NaCl, KCl, NaBr, CaCl.sub.2, CaBr.sub.2, MgCl.sub.2, MgBr.sub.2,
ZnBr.sub.2, acetate salts, sodium acetate, potassium acetate,
ammonium chloride (NH.sub.4Cl), potassium phosphate, sodium
formate, potassium formate, cesium formate, or combinations
thereof. In an aspect, the WSF (e.g., the base fluid of the WSF)
includes a brine including the salt to be detected.
In an aspect, the base fluid includes an aqueous fluid. Aqueous
fluids that may be used in the WSF include any aqueous fluid
suitable for use in subterranean applications, provided that the
aqueous fluid is compatible with the other components (e.g., shale
inhibitor) used in the WSF. For example, the aqueous fluid may
include water or a brine. In an aspect, the aqueous fluid includes
an aqueous brine. In an aspect, the WSF suitable for use in the
present disclosure may include any suitable salt(s). In such
aspect, the aqueous brine generally includes water and an inorganic
monovalent salt, an inorganic multivalent salt, or both. The
aqueous brine may be naturally occurring or artificially-created.
Water present in the brine may be from any suitable source,
examples of which include, but are not limited to, sea water, tap
water, freshwater, water that is potable or non-potable, untreated
water, partially treated water, treated water, produced water, city
water, well-water, surface water, liquids including water-miscible
organic compounds, and combinations thereof. The salt or salts in
the water may be present in an amount ranging from greater than
about 0% by weight to a saturated salt solution, alternatively from
about 1 wt. % to about 30 wt. %, or alternatively from about 5 wt.
% to about 10 wt. %, based on the weight of the salt solution. In
an aspect, the salt or salts in the water may be present within the
base fluid in an amount sufficient to yield a saturated brine. As
will be appreciated by one of skill in the art, and with the help
of this disclosure, the type and concentration of salt solutions
utilized as a base fluid is dependent on the WSF density (e.g.,
drilling fluid density, completion fluid density, etc.), which may
range from about 8 lb/gallon to about 20 lb/gallon, alternatively
from about 10 lb/gallon to about 18 lb/gallon, or alternatively
from about 12 lb/gallon to about 16 lb/gallon.
Nonlimiting examples of aqueous brines suitable for use in the
present disclosure include chloride-based, bromide-based,
phosphate-based or formate-based brines containing monovalent
and/or polyvalent cations, salts of alkali and alkaline earth
metals, or combinations thereof. Additional examples of suitable
brines include, but are not limited to brines including salts such
as NaCl, KCl, NaBr, CaCl.sub.2, CaBr.sub.2, MgCl.sub.2, MgBr.sub.2,
ZnBr.sub.2, acetate salts, sodium acetate, potassium acetate,
ammonium chloride (NH.sub.4Cl), potassium phosphate, sodium
formate, potassium formate, cesium formate, or combinations
thereof. In an aspect, the base fluid includes a brine.
In an aspect, the base fluid includes an emulsion. In such aspect,
the emulsion is an oil-in-water emulsion including a non-oleaginous
(e.g., an aqueous fluid of the type previously described herein)
continuous phase and an oleaginous (e.g., an oil-based fluid, such
as for example an oleaginous fluid) discontinuous phase. Oleaginous
fluids that may be used in the WSF include any oleaginous fluid
suitable for use in subterranean applications, provided that the
oleaginous fluid is compatible with the shale inhibitor and/or salt
used in the WSF. Examples of oleaginous fluids suitable for use in
a WSF include, but are not limited to, petroleum oils, natural
oils, synthetically-derived oils, oxygenated fluids, or
combinations thereof. In an aspect, the oleaginous fluid includes
diesel oil, kerosene oil, mineral oil, synthetic oils, aliphatic
hydrocarbons, polyolefins (e.g., alpha olefins, linear alpha
olefins and/or internal olefins), paraffins, silicone fluids,
polydiorganosiloxanes, oxygenated solvents, esters, diesters of
carbonic acid, alcohols, alcohol esters, ethers, ethylene glycol,
ethylene glycol monoalkyl ether, ethylene glycol dialkyl ether, or
combinations thereof, wherein the alkyl groups are methyl, ethyl,
propyl, butyl, and the like.
The base fluid may be present within the WSF in any suitable
amount. For example, the base fluid may be present within the WSF
in an amount of from about 10 wt. % to about 99 wt. %,
alternatively from about 20 wt. % to about 95 wt. %, or
alternatively from about 40 wt. % to about 90 wt. %, based on the
total weight of the WSF. Alternatively, the base fluid may include
the balance of the WSF after considering the amount of the other
components used. As will be appreciated by one of skill in the art,
and with the help of this disclosure, the amount of base fluid
(e.g., aqueous base fluid) in the WSF depends on the desired
density of the WSF.
In an aspect, the WSF suitable for use in the present disclosure
may include any suitable shale inhibitor.
Shale is a clay-rich sedimentary rock, wherein the shale includes
at least about 5 wt. % clay material, based on the total weight of
the shale. When shale is exposed to water (e.g., an aqueous fluid;
an aqueous-base fluid; a water-containing fluid, such as an
emulsion; etc.), the clay in the shale can adsorb water and swell,
thereby resulting in potential problems during drilling and/or
completion processes, such as viscosity build-up, bit balling,
wellbore caving, wellbore ballooning, subterranean formation
integrity loss, collapse of subterranean formation, etc.
Generally, a shale inhibitor refers to a chemical compound having
the ability to inhibit water-reactive formations (e.g.,
water-reactive subterranean formations; subterranean formations
having water-reactive minerals) from collapsing or losing integrity
when the formations come in contact with a water-containing fluid
(e.g., an aqueous fluid; an aqueous-base fluid; a water-containing
fluid, such as an emulsion; etc.); for example by limiting water
uptake by such formations. For purposes of the disclosure herein,
the term "water-reactive" refers to formations (e.g., subterranean
formations) and/or minerals thereof that can absorb water, uptake
water, react with water, and the like, or combinations thereof.
Water-reactive formations can encompass any subterranean formations
containing clay or clay-based materials, such as shale. For
purposes of the disclosure herein, the terms "shale inhibitor" and
"clay inhibitor" can be used interchangeably and refer to chemical
compounds having the ability to inhibit water uptake by
clay-containing subterranean formations (i.e., water-reactive
subterranean formations). Without wishing to be limited by theory,
clay contains hydrous aluminum silicates having hydroxyl ions that
are capable of forming hydrogen bonds. Further, without wishing to
be limited by theory, shale inhibitors are chemical compounds
having functional groups (e.g., amine functional groups, protonated
amine functional groups) that can form hydrogen bonds with the clay
(i.e., with the water and/or hydroxyl groups present in the clay),
thereby inhibiting water adsorption by the clay material, for
example by blocking sites available for hydrogen bonding and
rendering such sites unavailable for hydrogen bonding with water
molecules. Furthermore, and without wishing to be limited by
theory, the shale inhibitor may interact with the subterranean
formation via a variety of physical bonds, such as hydrogen bonds,
electrostatic interactions, van der Waals interactions, ionic
interactions, dipole-dipole interactions, and the like, or
combinations thereof.
In an aspect, the shale inhibitor can include a salt (e.g.,
potassium chloride (KCl), sodium chloride (NaCl)), a polymer (e.g.,
a high molecular weight polymer (e.g., a polyacrylamide)), a
charged polymer, or a combination thereof. For example, the shale
inhibitor can include an amine functional group, (e.g., a primary
amine functional group, a secondary amine functional group, a
tertiary amine functional group, or combinations thereof) and/or a
protonated amine functional group (e.g., a protonated primary amine
functional group, a protonated secondary amine functional group, a
protonated tertiary amine functional group, or combinations
thereof). Without wishing to be limited by theory, amine functional
groups and/or protonated amine functional groups in the amine-based
shale inhibitor can form hydrogen bonds with the clay (i.e., with
the water and/or hydroxyl groups present in the clay), thereby
inhibiting water adsorption by the clay material, for example by
blocking sites available for hydrogen bonding and rendering such
sites unavailable for hydrogen bonding with water molecules.
Further, without wishing to be limited by theory, the shale
inhibitor may minimize shale or clay hydration and thus prevent or
reduce the adsorption of water by downhole water-reactive
formations to prevent or reduce a loss of wellbore and/or
subterranean formation stability. In embodiments, the shale
inhibitor is not an amine-based shale inhibitor.
In an aspect, a shale inhibitor may be included within the WSF in a
suitable or effective amount (e.g., an amount effective to provide
desired shale inhibitory properties to the WSF). The resultant
amount of shale inhibitor that is necessary to impart desired shale
inhibitory properties to a WSF may be dependent upon a variety of
factors such as the composition of the WSF; the presence or absence
of various additives in the WSF; the intended formation location
where the WSF is expected to be used to inhibit water uptake; the
composition of the formation; the pressure of the formation; the
temperature of the formation; the diameter of the hole; and the
like; or combinations thereof.
In an aspect, a shale inhibitor may be present within the WSF in an
amount (e.g., target amount) of from about 0.01 wt. % to about 5
wt. %, alternatively from about 0.02 wt. % to about 4 wt. %, or
alternatively from about 0.03 wt. % to about 3 wt. %, based on the
total weight of the WSF. For purposes of the disclosure herein, the
target amount of shale inhibitor in the WSF refers to the desired
amount of shale inhibitor in the WSF; e.g., the amount of shale
inhibitor effective to provide desired shale inhibitory properties
to the WSF.
The WSF may further include additional additives as deemed
appropriate for improving the properties of the fluid. Such
additives may vary depending on the intended use of the fluid in
the wellbore. Examples of such additives include, but are not
limited to suspending agents, density reducing additives, settling
prevention agents, expansion additives, clays, salts, accelerants,
set retarders, lignosulfonates, defoamers, surfactants, dispersing
agents, fluid loss control agents, weighting materials,
dispersants, fillers, zeolites, barite, calcium sulfate, silica
flour, sand, slag, vitrified shale, fly ash, pozzolanic ash, lime,
formation conditioning agents, fluid absorbing materials, resins,
aqueous superabsorbers, viscosifying agents, gelling agents,
crosslinkers, mechanical property modifying additives, elastomers,
styrene-butadiene copolymers, conventional reinforcing materials,
carbon fibers, glass fibers, metal fibers, minerals fibers, and the
like, or combinations thereof. These additives may be introduced
singularly or in combination using any suitable methodology and in
amounts effective to produce the desired improvements in the
properties of the WSF. As will be appreciated by one of skill in
the art with the help of this disclosure, any of the components
and/or additives used in the WSF should be compatible with the
shale inhibitor used in the WSF composition.
In an aspect, the WSF as disclosed herein may be prepared by using
any suitable method or process. The components of the WSF (e.g.,
shale inhibitor, base fluid, additives, etc.) may be combined and
mixed in by using any mixing device compatible with the
composition, e.g., a mixer, a batch mixer, a batch mixer with
impellers and/or paddles, a blender, a batch blender, single ribbon
type blenders, double ribbon type blenders, horizontal blenders,
vertical blenders, inclined blenders, single or double ribbon type
blenders which could further be horizontal, vertical or inclined,
mixing eductors, dry powder eductors, dry powder eductor with
centrifugal pump followed by circulation loop, cyclone-type dry to
liquid mixer, inline static mixers, and the like, or any suitable
combination thereof.
In an aspect, the components of the WSF are combined at the well
site; alternatively, the components of the WSF are combined
off-site and are transported to and used at the well site. The
resulting WSF may be pumped downhole where it may function as
intended (e.g., prevent and/or reduce water uptake by
water-reactive formations).
As will be appreciated by one of skill in the art, and with the
help of this disclosure, a WSF including a shale inhibitor and/or
salt as disclosed herein may be used for preventing and/or reducing
water uptake by water-reactive formations in any suitable stage of
a wellbore's life, such as for example, during a drilling
operation, completion operation, etc.
In an aspect, a method of servicing a wellbore in a subterranean
formation can include detecting a shale inhibitor and/or salt in a
WSF (e.g., testing the WSF for the presence and/or amount of shale
inhibitor and/or salt in the WSF).
In some aspects, the shale inhibitor and/or salt may be detected in
a WSF prior to using the WSF in a wellbore servicing operation
(e.g., a first amount or concentration that is determined prior to
placing the WSF in the wellbore and/or subterranean formation,
prior to circulating the WSF in the wellbore and/or subterranean
formation); as will be discussed in more detail later herein. In
such aspects, the shale inhibitor and/or salt may be detected in a
WSF at any suitable time between preparing the WSF and placing the
WSF in the wellbore and/or subterranean formation. In such aspects,
the WSF can be placed in the wellbore and/or subterranean formation
subsequent to determining the amount of shale inhibitor and/or salt
in the WSF (e.g., post-testing of the WSF for the presence and/or
amount of shale inhibitor and/or salt in the WSF). In aspects,
prior to using the WSF in a wellbore servicing operation, the WSF
does not include a shale inhibitor and/or a salt.
As will be appreciated by one of skill in the art, and with the
help of this disclosure, determining the concentration (e.g., a
first concentration) of the shale inhibitor and/or salt in the WSF
subsequent to adding a known amount (e.g., target amount) of shale
inhibitor and/or salt to the WSF (and prior to use thereof via
placement in a wellbore) may provide validation of the detection
method and/or may allow for calibrating the detection method by
reconciling the known amount (e.g., target amount) of shale
inhibitor and/or salt added to the WSF with the detected amount. In
aspects where the known amount (e.g., target amount) of shale
inhibitor and/or salt added to the WSF and the detected amount are
the same, no action is needed (e.g., no reconciliation is
necessary). In aspects where the known amount (e.g., target amount)
of shale inhibitor and/or salt added to the WSF and the detected
amount are different, a correction factor can be employed to
reconcile (e.g., correlate) the known amount (e.g., target amount)
of shale inhibitor and/or salt added to the WSF with the detected
amount. As will be appreciated by one of skill in the art, and with
the help of this disclosure, the method of detecting the amount of
shale inhibitor and/or salt in the WSF might either overestimate or
underestimate the actual amount (e.g., known amount, target amount)
of shale inhibitor and/or salt added to the WSF. For example, a
correction factor could be calculated by dividing the detected
(e.g., measured, calculated) amount of shale inhibitor and/or salt
in the WSF by the actual amount (e.g., known amount, target amount)
of shale inhibitor and/or salt added to the WSF; or by dividing the
actual amount (e.g., known amount, target amount) of shale
inhibitor and/or salt added to the WSF by the detected (e.g.,
measured, calculated) amount of shale inhibitor and/or salt in the
WSF. The correction factor (e.g., correlation factor) can be used
to correlate the known amount (e.g., target amount) of shale
inhibitor and/or salt added to the WSF with the detected amount.
The correction factor (e.g., correlation factor) can be further
used throughout testing of the WSF (e.g., subsequent to placing the
WSF in a wellbore and/or subterranean formation) to provide for a
more accurate determination of the amount of shale inhibitor and/or
salt in the WSF.
In other aspects, the shale inhibitor and/or salt may be detected
in a WSF subsequent to using the WSF in a wellbore servicing
operation (e.g., a second amount or concentration that is
determined subsequent to placing the WSF in the wellbore and/or
subterranean formation, subsequent to circulating the WSF in the
wellbore and/or subterranean formation); as will be discussed in
more detail later herein. In such aspects, the WSF may be placed in
the wellbore and/or subterranean formation pre-testing of the WSF
for the presence and/or amount of shale inhibitor and/or salt in
the WSF. In aspects, only the first or the second amount or
concentration of the shale inhibitor and/or the salt is determined.
For example, in aspects determination of a concentration of a salt
is performed subsequent to using the WSF in a wellbore servicing
operation.
In an aspect, the WSF may be utilized in a drilling and completion
operation.
In an aspect, the WSF is a drilling fluid. A drilling fluid, also
known as a drilling mud or simply "mud," is a fluid that is
circulated through a wellbore to yield a circulated drilling fluid,
while the wellbore is being drilled to facilitate the drilling
operation. Generally, a circulated drilling fluid can carry
cuttings up from downhole and around a drill bit, transport them up
an annulus, and allow their separation, followed by recycling the
drilling fluid to the drilling operation. Further, a drilling fluid
can cool and lubricate the drill bit, as well as reduce friction
between a drill string and the sides of the wellbore hole.
Furthermore, the drilling fluid aids in support of a drill pipe and
drill bit, and provides a hydrostatic pressure necessary to
maintain the integrity of the wellbore walls and prevent well
blowouts. The shale inhibitor and/or salt in the drilling fluid may
contact the subterranean formation. When the subterranean formation
includes clay and/or shale, at least a portion of the shale
inhibitor and/or salt may interact with the subterranean formation
to prevent and/or reduce water uptake by such water-reactive
formation (for example, and without wishing to be limited by
theory, by forming a physical bond such as a hydrogen bond with the
clay), wherein at least a portion of the shale inhibitor and/or
salt may be retained by the subterranean formation, thereby
depleting (e.g., reducing the amount of) the shale inhibitor and/or
salt in the drilling fluid. Salt may be incorporated into the
drilling fluid from the formation during the drilling operation.
Depending on the amount of shale inhibitor and/or salt detected in
the circulated drilling fluid, the amount of shale inhibitor and/or
salt in the drilling fluid may be adjusted (e.g., increased or
decreased) as necessary, as will be discussed in more detail later
herein.
In an aspect, the WSF (e.g., including the shale inhibitor and/or
salt) is a completion fluid. In an aspect, when desired (for
example, upon the cessation of drilling operations and/or upon
reaching a desired depth), the wellbore or a portion thereof may be
prepared for completion. In an aspect, the method of using a WSF
(e.g., including shale inhibitor and/or salt, such as a completion
fluid including an shale inhibitor and/or salt) may include
completing the wellbore. Typically, completion fluids are free of
solids. Generally, a completion fluid is placed in the well to
facilitate final operations prior to initiation of production, such
as setting screens, production liners, packers, downhole valves,
etc. The wellbore, or a portion thereof, may be completed by
providing a casing string within the wellbore and cementing or
otherwise securing the casing string within the wellbore. In such
an aspect, the casing string may be positioned (e.g., lowered into)
the wellbore to a desired depth prior to, concurrent with, or
following provision of the completion fluid. The completion fluid
may be displaced from the wellbore by pumping a flushing fluid, a
spacer fluid, and/or a suitable cementitious slurry downward
through an interior flowbore of the casing string and into an
annular space formed by the casing string and the wellbore walls.
When the cementitious slurry has been positioned, the cementitious
slurry may be allowed to set. The shale inhibitor and/or salt in
the completion fluid may contact the subterranean formation whereby
an amount of the shale inhibitor and/or salt in the completion may
increase or decrease. For example, when the subterranean formation
includes clay and/or shale, at least a portion of the shale
inhibitor and/or salt may interact with the subterranean formation
to prevent and/or reduce water uptake by such water-reactive
formation (for example, and without wishing to be limited by
theory, by forming a physical bond such as a hydrogen bond with the
clay), wherein at least a portion of the shale inhibitor and/or
salt may be retained by the subterranean formation, thereby
depleting (e.g., reducing the amount of) the shale inhibitor and/or
salt in the completion fluid. Depending on the amount of shale
inhibitor and/or salt detected in the displaced completion fluid,
the amount of shale inhibitor and/or salt introduced to the
subterranean formation (for example via a flushing fluid, a spacer
fluid, and/or a suitable cementitious slurry used to displace the
completion fluid) may be adjusted as necessary, as will be
discussed in more detail later herein.
In an aspect, a method of detecting a shale inhibitor and/or salt
in a WSF can include contacting an aliquot of the WSF with a
detector compound to form a detection solution. For purposes of the
disclosure herein, an aliquot of a liquid (e.g., WSF) refers to an
amount of the liquid that is sufficient for allowing the detection
of a shale inhibitor and/or salt. For example, an aliquot of the
WSF can be equal to or greater than about 0.001 milliliters (mL),
alternatively equal to or greater than about 0.01 mL, alternatively
equal to or greater than about 0.1 mL, alternatively equal to or
greater than about 1 mL, alternatively equal to or greater than
about 5 mL, alternatively equal to or greater than about 10 mL, or
alternatively equal to or greater than about 25 mL.
In aspects where the WSF is substantially solids-free, an aliquot
of the WSF can be contacted with the detector compound without any
further processing. For purposes of the disclosure herein, a liquid
is considered substantially solids-free when the amount of solids
in the WSF does not interfere with the detection of the shale
inhibitor and/or salt. As will be appreciated by one of skill in
the art, and with the help of this disclosure, whether solids
present in the WSF interfere with the detection of the shale
inhibitor and/or salt is dependent upon a variety of factors, such
as the amount of solids, the size and/or size distribution of
solids, the light absorbing properties of the solids, the light
diffraction properties of the solids, etc. For example, a
substantially solids-free WSF may include solids in an amount of
less than about 1 wt. %, alternatively less than about 0.1 wt. %,
alternatively less than about 0.01 wt. %, alternatively less than
about 0.001 wt. %, or alternatively less than about 0.0001 wt. %,
based on the total weight of the WSF.
In aspects where the WSF includes solids (e.g., the WSF includes
solids that may interfere with the detection of the shale inhibitor
and/or salt), at least a portion of the WSF may be subjected to a
solids removal procedure to yield a substantially solids-free WSF.
The solids in the WSF can be debris, mud, WSF additives, drill
cuttings, and the like, or combinations thereof. In an aspect, the
solids removal procedure can be selected from the group that
includes at least filtration, sedimentation, decantation,
centrifugation, screening, chemical dissolution, and combinations
thereof. For example, at least a portion of the WSF including an
undesirable amount of solids (e.g., solids that may interfere with
the detection of the shale inhibitor and/or salt) may be filtered
(e.g., via any suitable filter, such as a syringe filter) to yield
a filtrate (passing through a filter) and solids (retained onto a
filter), wherein the filtrate is the substantially solids-free WSF
and may be further subjected to shale inhibitor and/or salt
detection as disclosed herein. As another example, at least a
portion of the WSF including an undesirable amount of solids (e.g.,
solids that may interfere with the detection of the shale inhibitor
and/or salt) may be contacted with a chemical compound that may
convert the solids into soluble compounds (e.g., acid soluble
particles could be dissolved with an acid), thereby yielding the
substantially solids-free WSF which may be further subjected to
shale inhibitor and/or salt detection as disclosed herein. An
aliquot of the substantially solids-free WSF (e.g., an aliquot of
the filtrate) can be contacted with a detector compound to form the
detection solution.
In some aspects, the WSF may be subjected to more than one solids
removal procedure to yield a substantially solids-free WSF. For
example, a circulated drilling fluid may be subjected to
centrifugation or screening for the removal of cuttings, wherein
the resulting WSF is not solids-free and may be recycled to
circulating in the wellbore and/or subterranean formation; and
wherein an aliquot of the resulting WSF may be subjected to an
additional solids removal procedure, such as filtration, to yield
an aliquot of the WSF that is substantially solids-free and may be
further subjected to shale inhibitor and/or salt detection as
disclosed herein.
As will be appreciated by one of skill in the art, and with the
help of this disclosure, the amount of WSF subjected to a solids
removal procedure to yield a substantially solids-free WSF can be
greater than the aliquot of the substantially solids-free WSF
contacted with a detector compound to form the detection solution,
for example to allow for more than one aliquot to be subjected to
the detection method. Alternatively, the amount of WSF subjected to
a solids removal procedure to yield a substantially solids-free WSF
can be about the same as the aliquot of the substantially
solids-free WSF contacted with a detector compound to form the
detection solution.
In an aspect, the detector compound can include any suitable
compound that can undergo a chemical reaction with the shale
inhibitor and/or the salt and produce a colored reaction product
that has the ability to impart a color and/or color intensity to
the detection solution that is different from the color and/or
color intensity, respectively, of the aliquot of the WSF subjected
to detection as disclosed herein. As will be appreciated by one of
skill in the art, and with the help of this disclosure, if the
detector compound is colored, the color and/or color intensity of
the detection solution is different from the color and/or color
intensity, respectively, of the detector compound. In an aspect,
the detector compound is chromophore, for example a chromophore of
the type suitable for use with a detector such as Water Lens test
kit as described herein.
Nonlimiting examples of detector compounds suitable for use in the
present disclosure include methylene blue, ninhydrin,
indane-1,2,3-trione, hydrantin, quinhydrone, Dragendorff reagent,
chloranil, N-halosuccinimide, N-bromosuccinimide,
N-iodosuccinimide, a hydrazo compound, a diazonium salt,
fluorescein, fluorescein halide, fluorescein chloride, and the
like, or combinations thereof.
The detector compounds as disclosed herein, when combined with the
shale inhibitor and/or the salt, can undergo a chemical reaction
with the shale inhibitor and/or the salt, respectively, and produce
a colored reaction product.
In an aspect, the detector compound can be contacted in any
suitable amount with an aliquot of the WSF to yield the detection
solution. For example, the detector compound can be contacted with
an aliquot of the WSF in an amount of from about 0.01 mmol/liter to
about 200 mmol/liter, alternatively from about 0.1 mmol/liter to
about 150 mmol/liter, alternatively from about 1 mmol/liter to
about 100 mmol/liter, or alternatively from about 1 mmol/liter to
about 50 mmol/liter detector compound, based on the total volume of
the detection solution.
Without wishing to be limited by theory, and as will be appreciated
by one of skill in the art, and with the help of this disclosure,
color and/or color intensity can be detected by optical detection.
For purposes of the disclosure herein, the term "optical detection"
refers to detection performed visually by a human subject (e.g., an
observation by an operator) and/or detection performed by a
machine, for example detection with a spectrometer (e.g.,
ultraviolet-visible (UV-VIS) spectrometer and/or colorimeter) by
using an analytical technique, such as UV-VIS spectroscopy and/or
colorimetry, respectively.
In aspects, the color and/or color intensity can be detected by an
analyzer, such as a Water Lens test kit available from Water Lens,
LLC in Houston, Tex. Such a Water Lens test kit utilizes several
independent detection motifs in a 96-well plate format. Each 8-well
strip (12 strips to a plate) is filled with a different assay, each
of which contains a detector compound such as a colorimetric dye
(and optionally other constituents) sensitive to the presence of
the component(s)/analyte(s) (e.g., the shale inhibitor(s) and/or
the salt(s)) being measured. The assays can then be freeze-dried,
which can provide for a long shelf life, even in harsh
environments, and rapid rehydration upon introduction of the sample
of wellbore servicing fluid. The tests can be carefully formulated
to be compatible with specific analytes.
The analyzer (e.g., Water Lens test kit) can include a colorimeter
that operates on the principle of colorimetric absorption by
photosensitive dyes (e.g., one or more detector compounds such as
dyes including chromophores). When the dyes bind to respective
analytes, the photometric spectra of the dyes change. These changes
can be read by monitoring the absorbance of light at specific
wavelengths as light passes through the sample(s). The absorbance
characteristics can be read by a colorimeter, and the data
generated can be used to calculate the concentration of the
particular analyte in each sample of the wellbore servicing fluid,
for example via software.
Generally, color is associated specifically with electromagnetic
radiation (e.g., visible light) of a certain range of wavelengths
visible to the human eye, for example electromagnetic radiation
with a wavelength between about 380 nanometers (nm) and about 760
nm (visible spectrum). When all wavelengths of visible light are
present, the light appears "white" to a human. Colored materials
(e.g., compounds, solids, liquids, solutions, gases) are colored
because of the absorption of visible light (e.g., visible
electromagnetic radiation). The color is a result of the material
absorbing a certain color of light, leading to the visual
perception of the compound being the complementary color. If any
wavelength is removed (absorbed) from the visible light, a human
perceives the remaining combination of wavelengths of light as the
"complementary" color. For example, when light passes through a
liquid (e.g., colored solution), a characteristic portion of
wavelengths can be absorbed. If wavelengths of light from a certain
region of the spectrum are absorbed by a material, then the
materials will appear to be the complementary color to a human
operator. For example, if violet light with wavelength of 400 nm is
absorbed by a liquid, the liquid will visually appear yellow. As
another example, if blue light with wavelength of 450 nm is
absorbed by a liquid, the liquid will visually appear orange. As
yet another example, if green light with wavelength of 530 nm is
absorbed by a liquid, the liquid will visually appear purple.
In an aspect, the detection solution can be characterized by at
least one absorption peak wavelength in the range of from about 380
nm to about 760 nm, alternatively from about 390 nm to about 750
nm, alternatively from about 400 nm to about 740 nm, alternatively
from about 380 nm to about 460 nm, or alternatively from about 460
nm to about 760 nm. In such aspect, the detection solution is
characterized by a visible color (e.g., a color that can be
visually perceived by a human upon visual observation of the
detection solution), thereby the detection of the shale inhibitor
and/or the salt can be performed via optical detection (e.g.,
visual detection and/or spectroscopic detection). For purposes of
the disclosure herein, the terms "absorption peak wavelength,"
"maximum absorption wavelength," and "wavelength of maximum
absorbance" (.lamda..sub.max) can be used interchangeably, and
refer to the wavelength where a specific compound or mixture of
compounds displays the highest absorbance (i.e., the highest
absorption intensity) at a given concentration. As will be
appreciated by one of skill in the art, and with the help of this
disclosure, a specific compound or mixture of compounds can be
characterized by a local maximum absorbance and/or an absolute
maximum absorbance, wherein the local maximum absorbance refers to
the maximum absorbance intensity in a given wavelength range (e.g.,
the maximum absorbance intensity in a wavelength range of from
about 500 nm to about 600 nm), and wherein the absolute maximum
absorbance refers to the maximum absorbance intensity across the
entire investigated wavelength range (e.g., the maximum absorbance
intensity across the entire wavelength range of from about 380 nm
to about 760 nm). Further, and as will be appreciated by one of
skill in the art, and with the help of this disclosure, when a
specific compound or mixture of compounds displays a single
absorption peak across the entire investigated wavelength range,
the local maximum absorbance and the absolute maximum absorbance
are the same; and when a specific compound or mixture of compounds
displays two or more absorption peaks across the entire
investigated wavelength range, the peak with the highest absorption
intensity across the entire investigated wavelength range displays
the absolute maximum absorbance, while the peaks other than the
peak with the highest absorption intensity display local maximum
absorbances. Furthermore, and as will be appreciated by one of
skill in the art, and with the help of this disclosure, an
absorption peak wavelength may correspond to a local maximum
absorbance and/or an absolute maximum absorbance. Absorption peak
wavelengths are characteristic to each colored compound.
Generally, and without wishing to be limited by theory, colorimetry
is an analytical technique (e.g., spectroscopic technique) that can
be used to determine the amount (e.g., concentration) of colored
compounds in solutions by the application of the Beer-Lambert law,
which states that the concentration of a solute is proportional to
the absorbance (i.e., absorption intensity). Typically, colorimetry
uses the entire visible spectrum (i.e., white light or visible
light) or light with a specific wavelength, thereby allowing for
the complementary color of the absorbed radiation to be observed as
transmitted light. Colorimetry can use a particular wavelength when
the compound to be detected is known, and consequently the
wavelength at which such compound absorbs is known. Colorimetry
does not scan the entire visible light spectrum (as opposed to
UV-VIS spectroscopy). Further, colorimetry does not employ a
reference sample concurrently with a colored sample for detection.
Colorimetry is performed with a colorimeter. A colorimeter may
analyze a sample in a laboratory setting. Alternatively, a portable
colorimeter may be employed for sample analysis in the field (i.e.,
on location; in real-time).
In an aspect, a method of detecting a shale inhibitor and/or a salt
in a WSF can include detecting an absorption intensity for the
detection solution at a wavelength within about .+-.20%,
alternatively within about .+-.10%, alternatively within about
.+-.5%, alternatively within about .+-.1% of the at least one
absorption peak wavelength (.lamda..sub.max), or alternatively at
about the at least one absorption peak wavelength
(.lamda..sub.max). Generally, and without wishing to be limited by
theory, across the light spectrum wavelengths, colored compounds
absorb radiation via peaks (as opposed to lines), owing to complex
electronic transitions within the molecules of the colored
compounds. Further, and without wishing to be limited by theory,
the absorption intensity can be measured at any wavelength under
the absorption peak; however, measuring the absorption intensity at
the at least one absorption peak wavelength (.lamda..sub.max) will
yield the greatest detection sensitivity (owing to the steepest
slope of a calibration curve relating absorption intensity to
concentration). Furthermore, and without wishing to be limited by
theory, the absorption intensity is proportional to the amount
(e.g., concentration) of colored compound (e.g., colored reaction
product formed by the chemical reaction between the shale inhibitor
and/or salt and the detector compound), in accordance with the
Beer-Lambert law. As will be appreciated by one of skill in the
art, and with the help of this disclosure, the further the
wavelength at which the absorption intensity is measured is from
the at least one absorption peak wavelength (.lamda..sub.max), the
greater the error in determining the amount (e.g., concentration)
of colored compound (e.g., colored reaction product formed by the
chemical reaction between the shale inhibitor and/or salt and the
detector compound).
In an aspect, detecting an absorption intensity for the detection
solution at a wavelength within about .+-.20% of the at least one
absorption peak wavelength (.lamda..sub.max) can include visually
detecting the color intensity of the detection solution. For
example, a human (e.g., an operator) can visually detect the color
intensity of the solution, such as deep purple versus light purple,
mildly deep red versus extremely deep red.
In an aspect, detecting an absorption intensity for the detection
solution at a wavelength within about .+-.20% of the at least one
absorption peak wavelength (.lamda..sub.max) can include
spectroscopically detecting an absorption intensity of the
detection solution, for example via colorimetry and/or UV-VIS
spectroscopy, as disclosed herein.
In an aspect, a method of detecting a shale inhibitor and/or salt
in a WSF can further include heating the detection solution, e.g.,
heating the detection solution prior to detecting an absorption
intensity for the detection solution at a wavelength within about
.+-.20% of the at least one absorption peak wavelength. The
detection solution can be heated by using any suitable methodology
(e.g., a heater, a heat exchanger, a fired heater, a burner, a
heating mantle, a heating element, etc.).
In an aspect, the detection mixture can be heated to a temperature
of from about 30.degree. C. to about a boiling point of the
detection solution, alternatively from about 30.degree. C. to about
100.degree. C., alternatively from about 35.degree. C. to about
95.degree. C., alternatively from about 40.degree. C. to about
90.degree. C., or alternatively from about 50.degree. C. to about
75.degree. C. Without wishing to be limited by theory, heating the
detection solution can speed up (e.g., increase the rate of) the
reaction between the detector compound and the shale inhibitor
and/or the salt. As will be appreciated by one of skill in the art,
and with the help of this disclosure, and without wishing to be
limited by theory, colored compounds absorbance generally varies
with temperature, and consequently the heated detection solution
can be cooled to ambient temperature (e.g., room temperature, a
temperature of from about 15.degree. C. to about 30.degree. C.)
prior to detecting an absorption intensity for the detection
solution at a wavelength within about .+-.20% of the at least one
absorption peak wavelength. For example, the detection solution may
be allowed to reach ambient temperature by losing heat to the
surrounding environment. As another example, the detection solution
can be cooled by using any suitable methodology (e.g., a cooler, a
heat exchanger, a cooling bath, an ice bath, a cooling element,
etc.).
In an aspect, a method of detecting a shale inhibitor and/or salt
in a WSF can include comparing the absorption intensity of the
detection solution at the wavelength within about .+-.20% of the at
least one absorption peak wavelength (.lamda..sub.max) with a
target absorption intensity of the shale inhibitor and/or the salt,
respectively, to determine the amount of shale inhibitor and/or
salt in the WSF.
In an aspect, comparing the absorption intensity of the detection
solution at the wavelength within about .+-.20% of the at least one
absorption peak wavelength (.lamda..sub.max) with a target
absorption intensity of the shale inhibitor and/or salt includes
optically comparing the color and/or color intensity of the
detection solution with a target color and/or color intensity,
respectively. For purposes of the disclosure herein, the terms
"optically comparing" and "optical comparison" refers to a
comparison performed visually by a human subject (e.g., an
operator) and/or a comparison performed by a machine, such as a
computing device (e.g., computer, laptop, calculator, etc.) used in
conjunction with (e.g., connected to, networked with, etc.) a
spectrometer (e.g., UV-VIS spectrometer and/or colorimeter).
In an aspect, determining the amount of shale inhibitor and/or salt
in the WSF further includes visually comparing a visually observed
color and/or color intensity of the detection solution with a
reference color chart that correlates color and/or color intensity,
respectively, with the amount of the shale inhibitor and/or salt.
In an aspect, a reference color chart can be constructed for each
detector compound, given that each detector compound might provide
for a detection solution having a different color or a different
color hue. For example, it is easier to visually compare a red
color to a reference color chart that employs the same red color
than it is to compare a red color to a reference color chart that
employs a red color having an orange hue. A reference color chart
can be constructed for a specific detector compound by preparing
detection solutions having known concentrations of the shale
inhibitor and/or salt, and recording the color corresponding to
each concentration, for example by taking a picture of the
detection solution, and noting the concentration of the shale
inhibitor and/or salt that corresponds to the color and color
intensity in the picture. The reference color chart can generally
include two or more pictures relating the color and color intensity
of the detection solution to corresponding known concentrations of
the shale inhibitor and/or salt. As will be appreciated by one of
skill in the art, and with the help of this disclosure, and without
wishing to be limited by theory, the higher the concentration of
the shale inhibitor and/or salt, the more intense (e.g., deeper)
the color of the detection solution; and the lower the
concentration of the shale inhibitor and/or salt, the less intense
(e.g., paler) the color of the detection solution.
As will be appreciated by one of skill in the art, and with the
help of this disclosure, when the color of the detection solution
changes based on the type of shale inhibitor and/or salt as well as
the detector compound (e.g., some detector compounds may yield one
color for shale inhibitors including primary amines, and a
different color for shale inhibitors including secondary and/or
tertiary amines), it may be necessary to create a reference color
chart for a specific detector compound used in conjunction (e.g.,
paired) with a specific shale inhibitor and/or salt. Further, and
as will be appreciated by one of skill in the art, and with the
help of this disclosure, while as little as two concentrations
(e.g., a low concentration and a high concentration) can be used
for creating a reference color chart, using more than two,
alternatively more than three, alternatively more than four,
alternatively more than five, alternatively from three to about
twenty, alternatively from about five to about fifteen, or
alternatively from about five to about ten concentrations for
creating a reference color chart can significantly improve the
accuracy of determining the amount of shale inhibitor and/or salt
in the WSF.
In some aspects, visually comparing the color and/or color
intensity of the detection solution with the reference color chart
can include matching the color and/or color intensity of the
detection solution with the closest color and/or color intensity,
respectively, on the reference color chart, wherein the closest
color and/or color intensity determines the amount of the shale
inhibitor and/or salt in the WSF. In other aspects, visually
comparing the color and/or color intensity of the detection
solution with the reference color chart can include matching the
color and/or color intensity of the detection solution with the
closest two colors and/or color intensities, respectively, on the
reference color chart, followed by estimating the amount of the
shale inhibitor and/or salt in the WSF between the amounts
corresponding to the closest two colors and/or color intensities,
respectively.
In some aspects, the reference color chart can include images or
pictures of detection solutions correlated with known
concentrations of the shale inhibitor and/or salt printed on an
appropriate substrate, such as paper (e.g., paper reference color
chart), cardboard (e.g., cardboard reference color chart), metal
(e.g., metal reference color chart), plastic (e.g., plastic
reference color chart), and the like, or combinations thereof. In
other aspects, the reference color chart including images or
pictures of detection solutions correlated with known
concentrations of the shale inhibitor and/or salt can be displayed
on an electronic screen, such as a computer monitor, a laptop
monitor, a phone screen, and the like, or combinations thereof.
In an aspect, comparing the absorption intensity of the detection
solution at the wavelength within about .+-.20% of the at least one
absorption peak wavelength (.lamda..sub.max) with a target
absorption intensity of the shale inhibitor and/or salt includes
using a calibration curve that correlates absorption intensity at
the wavelength within about .+-.20% of the at least one absorption
peak wavelength (.lamda..sub.max) with the amount of the shale
inhibitor and/or salt (e.g., known amount of the shale inhibitor
and/or salt).
In an aspect, a calibration curve can be constructed for each
detector compound, given that each detector compound might provide
for a detection solution having a different absorption peak
wavelength (.lamda..sub.max) (e.g., different color or a different
color hue). A calibration curve can be constructed for a specific
detector compound by preparing detection solutions having known
concentrations of the shale inhibitor and/or salt; subjecting the
detection solutions to spectroscopy (e.g., UV-VIS spectroscopy
and/or colorimetry); and plotting the known concentrations of the
shale inhibitor and/or salt as a function of the corresponding
measured absorption intensity. As will be appreciated by one of
skill in the art, and with the help of this disclosure, while the
calibration curve can be constructed (e.g., drawn) with as little
as two absorption intensity measurements corresponding to two
different known concentrations of the shale inhibitor and/or salt,
at least three absorption intensity measurements corresponding to
three different known concentrations of the shale inhibitor and/or
salt can be used for constructing the calibration curve, preferably
as many absorption intensity measurements as it is deemed to be
statistically significant for any particular case (e.g., any
particular detector compound, any particular pair of detector
compound and shale inhibitor and/or salt).
Further, without wishing to be limited by theory, and as will be
appreciated by one of skill in the art, and with the help of this
disclosure, a calibration curve is generally accompanied by a
mathematical equation describing the calibration curve, and the
mathematical equation can be used as well for translating the
absorption intensity into the amount of shale inhibitor and/or salt
in the WSF, for example by entering into the equation the measured
absorption intensity and calculating the corresponding amount of
shale inhibitor and/or salt in the WSF.
Furthermore, as will be appreciated by one of skill in the art, and
with the help of this disclosure, sometimes spectrometers (e.g.,
colorimeter, portable colorimeter, UV-VIS spectrometer, portable
UV-VIS spectrometer) can display a systematic error or bias, and as
such it may be desired to construct the calibration curve with the
same spectrometer that is used for measuring the absorption
intensity.
In an aspect, a method of detecting a shale inhibitor and/or salt
in a WSF can include comparing the amount of shale inhibitor and/or
salt in the WSF with a target amount of the shale inhibitor and/or
salt.
In some aspects, the amount of shale inhibitor and/or salt in the
WSF can be about the same as the target amount of the shale
inhibitor and/or salt. In such aspects, the WSF can be placed in
the wellbore and/or subterranean formation where it may function as
intended (e.g., prevent and/or reduce water uptake by
water-reactive formations).
In other aspects, the amount of shale inhibitor and/or salt in the
WSF can be different (e.g., less, lower, more, greater) than the
target amount of the shale inhibitor and/or salt. In such aspects,
the determined amount of shale inhibitor and/or salt in the WSF can
indicate a variance between the actual amount of the shale
inhibitor and/or salt in the WSF and the desired or target amount
of the shale inhibitor and/or salt. For example, such variance can
range from greater than about 0% (e.g., wherein very little shale
inhibitor and/or salt has been depleted from or incorporated into
the WSF, for example shale inhibitor and/or salt being lost to the
formation or salt being incorporated from the formation) to about
100% (e.g., wherein substantially all of the shale inhibitor and/or
salt has been depleted from the WSF, for example by being lost to
the formation).
In an aspect, the amount of shale inhibitor and/or salt in the WSF
can be lower than the target amount of the shale inhibitor and/or
the salt, respectively. For example, the amount of shale inhibitor
and/or salt in the WSF can be equal to or greater than about 1%,
alternatively equal to or greater than about 5%, alternatively
equal to or greater than about 10%, alternatively equal to or
greater than about 15%, alternatively equal to or greater than
about 20%, alternatively equal to or greater than about 25%,
alternatively equal to or greater than about 30%, alternatively
equal to or greater than about 35%, alternatively equal to or
greater than about 40%, alternatively equal to or greater than
about 45%, alternatively equal to or greater than about 50%,
alternatively equal to or greater than about 55%, alternatively
equal to or greater than about 60%, alternatively equal to or
greater than about 65%, alternatively equal to or greater than
about 70%, alternatively equal to or greater than about 75%,
alternatively equal to or greater than about 80%, alternatively
equal to or greater than about 85%, alternatively equal to or
greater than about 90%, alternatively equal to or greater than
about 95%, alternatively equal to or greater than about 99%, or
alternatively about 100% lower than the target amount of the shale
inhibitor and/or salt. In some aspects, the amount of shale
inhibitor and/or salt in the WSF can be greater than the target
amount of the shale inhibitor and/or the salt, respectively. For
example, during a drilling operation, the WSF may encounter
different formation layers that require different levels of
inhibition (e.g., require different concentrations of shale
inhibitor and/or salt), and as such the WSF may have an amount of
shale inhibitor and/or salt that is greater than the amount
required in a specific portion of the subterranean formation. As
will be appreciated by one of skill in the art, and with the help
of this disclosure, the amount of shale inhibitor and/or salt in
the WSF may be increased over time, for example as a result of
encountering more reactive formations.
In some aspects, the amount of shale inhibitor and/or salt in the
WSF can be less than the target amount of the shale inhibitor
and/or salt by a threshold amount. For purposes of the disclosure
herein, the threshold amount of shale inhibitor and/or salt is
defined as the difference between the amount (e.g., actual amount,
measured amount) of shale inhibitor and/or salt in the WSF and the
target amount of the shale inhibitor and/or the salt, respectively.
Further, for purposes of the disclosure herein, the threshold
amount of shale inhibitor and/or salt refers to the amount of shale
inhibitor and/or salt that is "missing" from the WSF (e.g., the
amount of shale inhibitor and/or salt that has been depleted from
the WSF, for example by being lost to the formation) and which
requires supplementation of shale inhibitor and/or salt into the
WSF, in order to provide for a WSF having the target amount of the
shale inhibitor and/or the salt, respectively.
In aspects where the amount of shale inhibitor and/or salt in the
WSF is less than the target amount of the shale inhibitor and/or
the salt, respectively, by an amount that is equal to or greater
than a threshold amount, the WSF may require further processing
prior to being used in a wellbore servicing operation (e.g.,
supplemental shale inhibitor and/or salt may be added to the WSF,
in order to provide for a WSF having the target amount of the shale
inhibitor and/or the salt, respectively).
As will be appreciated by one of skill in the art, and with the
help of this disclosure, the threshold amount of shale inhibitor
and/or salt that dictates whether a WSF requires or does not
require addition of supplemental shale inhibitor, salt, and/or base
fluid, may depend on a variety of factors, such as the type of
wellbore servicing operation, the composition of the WSF, the type
and/or configuration of the wellbore, the type of subterranean
formation, the subterranean formation conditions (e.g.,
temperature, pressure, etc.), and the like, or combinations
thereof.
The threshold amount of shale inhibitor and/or salt can be
expressed as a percentage (%) of the target amount of the shale
inhibitor and/or the salt, respectively. For example, the threshold
amount of shale inhibitor and/or salt can be equal to or greater
than about 1%, alternatively equal to or greater than about 5%,
alternatively equal to or greater than about 10%, alternatively
equal to or greater than about 15%, alternatively equal to or
greater than about 20%, alternatively equal to or greater than
about 25%, alternatively equal to or greater than about 30%,
alternatively equal to or greater than about 35%, alternatively
equal to or greater than about 40%, alternatively equal to or
greater than about 45%, alternatively equal to or greater than
about 50%, alternatively equal to or greater than about 55%,
alternatively equal to or greater than about 60%, alternatively
equal to or greater than about 65%, alternatively equal to or
greater than about 70%, alternatively equal to or greater than
about 75%, alternatively equal to or greater than about 80%,
alternatively equal to or greater than about 85%, alternatively
equal to or greater than about 90%, alternatively equal to or
greater than about 95%, alternatively equal to or greater than
about 99%, or alternatively about 100% of the target amount of the
shale inhibitor and/or the salt, respectively.
In aspects where the amount of shale inhibitor and/or salt in the
WSF is less than the target amount of the shale inhibitor and/or
the salt, respectively, by an amount that is lower than the
threshold amount, the WSF may be used in a wellbore servicing
operation without further processing (e.g., without adding
supplemental shale inhibitor and/or salt to the WSF). For example,
at least a portion of the WSF may be placed in the wellbore and/or
subterranean formation where it may function as intended (e.g.,
prevent and/or reduce water uptake by water-reactive
formations).
In some aspects, the amount of shale inhibitor and/or salt in the
WSF can be greater than the target amount of the shale inhibitor
and/or the salt, respectively. In aspects where the amount of shale
inhibitor and/or salt in the WSF is greater than the target amount
of the shale inhibitor and/or the salt, respectively, the WSF may
be used in a wellbore servicing operation without further
processing (e.g., without adjusting the amount of shale inhibitor
and/or salt in the WSF). As will be appreciated by one of skill in
the art, and with the help of this disclosure, the amount of shale
inhibitor and/or salt in the WSF may become greater than the target
amount of the shale inhibitor and/or salt owing to evaporation of
water from the WSF, overtreatment of shale inhibitor and/or salt in
the WSF (e.g., adding excess shale inhibitor and/or salt to the
WSF), influx of shale inhibitor and/or salt into the WSF, and the
like, or combinations thereof.
In aspects where the amount of shale inhibitor and/or salt in the
WSF is within about 1%, alternatively within about 5%,
alternatively within about 10%, alternatively within about 15%,
alternatively within about 20%, or alternatively within about 25%
of the target amount of the shale inhibitor and/or the salt,
respectively, the WSF may be used in a wellbore servicing operation
without further processing (e.g., without adding supplemental shale
inhibitor, salt, base fluid, etc., to the WSF). As will be
appreciated by one of skill in the art, and with the help of this
disclosure, when the amount of shale inhibitor and/or salt in the
WSF varies by a relatively small amount (e.g., less than about 1%,
alternatively less than about 5%, alternatively less than about
10%) from the target amount of the shale inhibitor and/or the salt,
respectively, at least a portion of such variance can be owed to
experimental error factors, such as operator error, measuring
errors, temperature variation, experimental noise, and the like, or
combinations thereof; and in such cases it may not be necessary to
adjust the amount of shale inhibitor and/or salt in the WSF.
In an aspect, a method of servicing a wellbore in a subterranean
formation can include adjusting the amount of shale inhibitor
and/or salt in the WSF to provide for a WSF (e.g., an adjusted WSF,
a corrected WSF, a supplemented WSF) having the target amount of
the shale inhibitor and/or the salt, respectively.
In aspects where the amount of shale inhibitor and/or salt in the
WSF varies by equal to or greater than the threshold amount from
the target amount of the shale inhibitor and/or the salt,
respectively, the WSF can be adjusted (e.g., contacted with an
effective supplemental amount of shale inhibitor, salt, base fluid,
etc.) to provide for the WSF having the target amount of the shale
inhibitor and/or the salt, respectively.
In an aspect, the effective supplemental amount of can be
determined on-the-fly (e.g., in real-time); wherein the WSF having
the target amount of the shale inhibitor and/or the salt can be
prepared on-location (e.g., on-site; at a wellbore site), by adding
the effective supplemental amount of the shale inhibitor, the salt,
the base fluid, etc., to the WSF. For purposes of the disclosure
herein, the terms "on-the-fly" and "real-time" can be used
interchangeably and collectively refer to an action that is
performed during an ongoing wellbore servicing operation; wherein
performing such action can result in changes to an ongoing wellbore
servicing operation on a time scale of less than about 30 minutes,
alternatively less than about 15 minutes, alternatively less than
about 10 minutes, alternatively less than about 5 minutes,
alternatively less than about 1 minute, alternatively less than
about 30 seconds, alternatively less than about 15 seconds,
alternatively less than about 10 seconds, alternatively less than
about 5 seconds, or alternatively less than about 1 second.
For purposes of the disclosure herein, the term "real-time" refers
to an action that is performed on a time scale that allows for
feedback (e.g., real-time feedback) to an ongoing wellbore
servicing operation, wherein the feedback affects the ongoing
wellbore servicing operation. For example, real-time data, such as
the measured (i.e., actual) amount of shale inhibitor and/or salt
in the WSF, can be provided about instantly (e.g., as soon as it is
obtained) to a decision factor (e.g., an operator, a computing
device), wherein the decision factor can decide or determine
whether it is necessary to add the supplemental amount (e.g., of
shale inhibitor, salt, base fluid, etc.) to the WSF or not, on a
time scale (i.e., about instantly, in real-time) that can affect
the ongoing wellbore servicing operation. In some aspects, the
computing device can be interfaced or networked with a spectrometer
(e.g., colorimeter, portable colorimeter, UV-VIS spectrometer,
portable UV-VIS spectrometer). In an aspect, the amount of shale
inhibitor and/or salt present in a WSF can be tested on-the-fly
during a wellbore servicing operation, and the WSF can be
supplemented in real-time such that the wellbore servicing
operation does not have to be halted, and thus costly unproductive
time can be avoided or minimized.
As will be appreciated by one of skill in the art, and with the
help of this disclosure, employing visual detection and/or
spectroscopic detection with a portable spectrometer (e.g.,
portable colorimeter and/or portable UV-VIS spectrometer) of the
absorption intensity for the detection solution can generally
result in obtaining data regarding the amount of shale inhibitor
and/or salt in the WSF in real-time (as opposed to introducing a
delay which may be significant by sending a WSF sample to be
analyzed in a laboratory setting).
In an aspect, the effective supplemental amount (e.g., of shale
inhibitor, salt, base fluid, etc.) can be determined in real-time;
wherein the WSF having the target amount of the shale inhibitor
and/or the salt, respectively, can be prepared in real-time, by
adding the effective supplemental amount (e.g., of supplemental
shale inhibitor, salt, base fluid, etc.) to the WSF; and wherein
the WSF having the target amount of the shale inhibitor and/or the
salt, respectively, may be placed in the wellbore and/or
subterranean formation where it may function as intended (e.g.,
prevent and/or reduce water uptake by water-reactive
formations).
In an aspect, a method of servicing a wellbore in a subterranean
formation can include (a) preparing a drilling fluid (e.g.,
including a base fluid, shale inhibitor, and/or a salt, wherein the
shale inhibitor and/or the salt is present in the drilling fluid in
a target amount (e.g., greater than or equal to 0)); (b)
circulating the drilling fluid in the wellbore and/or subterranean
formation to yield a circulated drilling fluid; (c) subjecting at
least a portion of the circulated drilling fluid to solids removal
to yield a substantially solids-free circulated drilling fluid; (d)
contacting an aliquot of the solids-free circulated drilling fluid
with a detector compound to form a detection solution; wherein the
detection solution is characterized by at least one absorption peak
wavelength (.lamda..sub.max) in the range of from about 380 nm to
about 760 nm; (e) detecting an absorption intensity for the
detection solution at a wavelength within about .+-.20% of the at
least one absorption peak wavelength; (f) comparing the absorption
intensity of the detection solution at the wavelength within about
.+-.20% of the at least one absorption peak wavelength with a
target absorption intensity of the shale inhibitor and/or the salt
to determine the amount of shale inhibitor and/or salt in the
circulated drilling fluid; (g) comparing the amount of shale
inhibitor and/or salt in the circulated drilling fluid with the
target amount of the shale inhibitor and/or salt, wherein the
amount of shale inhibitor and/or salt in the circulated drilling
fluid varies by equal to or greater than a threshold amount from
the target amount of the shale inhibitor and/or salt; (h)
responsive to (g), determining an amount of supplemental shale
inhibitor and/or salt effective to provide for the circulated
drilling fluid having the target amount of the shale inhibitor
and/or salt, and contacting the circulated drilling fluid with the
effective amount of supplemental shale inhibitor and/or salt
on-the-fly; and (i) recycling at least a portion of the circulated
drilling fluid to the wellbore and/or subterranean formation. In
such aspect, the absorption intensity for the detection solution
can be detected visually (e.g., visual detection) and/or with a
spectrometer, such as a colorimeter, portable colorimeter, UV-VIS
spectrometer, portable UV-VIS spectrometer, etc. (e.g.,
spectroscopic detection).
In an aspect, a method of servicing a wellbore in a subterranean
formation can include (a) preparing a drilling fluid including a
base fluid, shale inhibitor, and/or a salt, wherein the shale
inhibitor and/or the salt is present in the drilling fluid in a
target amount (e.g., a target amount of greater than or equal to
zero); (b) circulating the drilling fluid in the wellbore and/or
subterranean formation to yield a circulated drilling fluid; (c)
subjecting at least a portion of the circulated drilling fluid to
solids removal to yield a substantially solids-free circulated
drilling fluid; (d) contacting an aliquot of the solids-free
circulated drilling fluid with a detector to form a detection
solution; wherein the detection solution is characterized by a
first absorption peak wavelength (first .lamda..sub.max) (nm) and
optionally by a second absorption peak wavelength (second
.lamda..sub.max); and wherein the detector is contacted with the
aliquot of the solids-free circulated drilling fluid in an amount
of from about 1 mmol/liter to about 50 mmol/liter detector, based
on the total volume of the detection solution; (e) detecting an
absorption intensity for the detection solution at a wavelength
within about .+-.20% of the first absorption peak wavelength and
optionally the second absorption peak wavelength; (f) comparing the
absorption intensity of the detection solution at the wavelength
within about .+-.20% of the first absorption peak wavelength and
optionally the second absorption peak wavelength with a target
absorption intensity at the wavelength within about .+-.20% of the
first absorption peak wavelength and optionally the second
absorption peak wavelength, respectively of the shale inhibitor
and/or the salt to determine the amount of shale inhibitor and/or
salt in the circulated drilling fluid; (g) comparing the amount of
shale inhibitor and/or salt in the circulated drilling fluid with
the target amount of the shale inhibitor and/or the salt, wherein
the amount of shale inhibitor and/or salt in the circulated
drilling fluid varies by equal to or greater than a threshold
amount from the target amount of the shale inhibitor and/or the
salt; (h) responsive to (g), determining a supplemental amount of
shale inhibitor, salt, and/or base fluid effective to provide for
the circulated drilling fluid having the target amount of the shale
inhibitor and/or the salt, and contacting the circulated drilling
fluid with the effective supplemental amount of the shale
inhibitor, the salt, and/or the base fluid in real-time; and (i)
recycling at least a portion of the circulated drilling fluid to
the wellbore and/or subterranean formation. In such aspect, the
absorption intensity for the detection solution can be detected
visually (e.g., visual detection) and/or with a spectrometer, such
as a colorimeter, portable colorimeter, UV-VIS spectrometer,
portable UV-VIS spectrometer, etc. (e.g., spectroscopic detection).
In aspects where the absorption intensity for the detection
solution is detected visually, the color of the detection solution
can be purple, blue, or another color. In aspects where the
absorption intensity for the detection solution is detected
spectroscopically, the detection solution can be subjected to
ultraviolet-visible (UV-VIS) spectroscopy and/or colorimetry in a
portable UV-VIS spectrometer and/or a portable colorimeter,
respectively.
In an aspect, the method of servicing a wellbore in a subterranean
formation including detecting a shale inhibitor and/or a salt in a
WSF as disclosed herein may display advantages when compared with
conventional methods of servicing a wellbore in a subterranean
formation. The method of detecting a shale inhibitor and/or a salt
in a WSF as disclosed herein may advantageously provide for
acquiring real-time data regarding the inhibitory properties of a
WSF (e.g., a drilling fluid) with respect to shale formations;
which in turn can result in real-time feedback that can allow for
correcting the amount of shale inhibitor and/or salt in the WSF.
Having the ability to adjust in real-time the amount of shale
inhibitor and/or salt in the WSF can advantageously reduce the
incidence of non-productive time.
In an aspect, the method of detecting a shale inhibitor and/or a
salt in a WSF as disclosed herein may advantageously provide for
effectively preventing and/or reducing water uptake by
water-reactive formations, which in turn can decrease the risk
and/or incidence of adverse events, such as viscosity build-up, bit
balling, wellbore caving, wellbore ballooning, subterranean
formation integrity loss, collapse of subterranean formation,
etc.
In an aspect, the method of detecting a shale inhibitor and/or a
salt in a WSF as disclosed herein may advantageously provide for a
more cost effective wellbore servicing operation. As will be
appreciated by one of skill in the art, and with the help of this
disclosure, adding a shale inhibitor and/or a salt to a WSF
increases the cost. The ability to accurately determine the
concentration of shale inhibitor and/or salt in the WSF could
advantageously prevent undue additions of shale inhibitor and/or
salt to the WSF, thereby lowering the cost. Additional advantages
of the method of servicing a wellbore in a subterranean formation
including detecting a shale inhibitor and/or salt in a WSF as
disclosed herein may be apparent to one of skill in the art viewing
this disclosure.
EXAMPLES
The embodiments having been generally described, the following
examples are given as particular embodiments of the disclosure and
to demonstrate the practice and advantages thereof. It is
understood that the examples are given by way of illustration and
are not intended to limit the specification or the claims in any
manner.
Example 1
FIG. 1 is a flow chart showing a representative method I for
measuring a salt content in a wellbore servicing fluid according to
this disclosure. Upon initiating the method I at start 10, method I
includes determining a wellbore servicing fluid (e.g., a drilling
fluid) water salinity at 20. As noted hereinabove, the wellbore
servicing fluid can be a drilling fluid (e.g., a drilling mud). The
drilling fluid can be a water based mud (WBM) or an oil based mud
(OBM). The water phase salinity of the wellbore servicing fluid can
be determined at step 20 via any available methods, such as,
without limitation, conductivity, colorimetry, or the like. As step
30, a known volume of the wellbore servicing fluid (e.g., a test
sample) is dosed into a container. The known volume of the wellbore
servicing fluid can be obtained subsequent circulation of the
wellbore servicing fluid downhole (e.g., subsequent passage of a
drilling fluid into a drill string in a wellbore, through a drill
bit, and back to a surface of the wellbore via an annulus). For
example, the known volume of the wellbore servicing fluid can be
obtained from a flow line or in a mud pit located at the surface
proximate a drilling rig.
As detailed hereinabove, the known volume can include a test sample
of the wellbore servicing fluid "as is", or solids can be removed
from the known volume of the wellbore servicing fluid and/or the
known volume of the wellbore servicing fluid can be diluted to
provide the test sample. For example, as indicated at step 40,
method I can further include adding a known amount of diluent
(e.g., water) to the known volume of wellbore servicing fluid and
optionally mixing to provide the test sample. Without intending to
be limited by theory, diluting the known volume may aid in
dispersing and/or separating any solids remaining in the known
volume of the wellbore servicing fluid to aid in obtaining a
substantially solids-free test sample. For example, step 40 can
include centrifuging the known volume of wellbore servicing fluid
to form a solids/bottom layer and an upper/supernatant liquid
layer, taking an amount from the supernatant (e.g., the water phase
of the WSF), and diluting the amount of supernatant with water
(optionally with mixing) to provide the test sample. Method I
includes at step 50, adding a detector compound such as a
chromophore dye to the test sample and mixing. Method I further
includes at step 60A, measuring the salt content of the test sample
utilizing the colorimetric method detailed herein. Method I further
includes, at step 70, reporting the data from step 60A to a
computer control system. At step 80A, method I includes,
determining (e.g., via the control system) a wellbore servicing
fluid (e.g., drilling fluid) treatment based on water phase
salinity (WPS) and optionally other shale inhibitors. Method I
includes, at step 90A, subjecting the wellbore servicing fluid of
the wellbore servicing system to the treatment, for example by
adding salt or water to the wellbore servicing fluid system (e.g.,
to the mud pit). At step 100, method I can include waiting for a
next time interval to test the wellbore servicing fluid system
(e.g., the mud system). The waiting time at step 100 can depend,
for example and without limitation, on the wellbore servicing fluid
system volume (e.g., the mud system volume) and pump rate. At 110,
the method includes initiating the method again by returning to
start 10.
Example 2
FIG. 2 is a flow chart showing a representative method II for
measuring a shale inhibitor content in a wellbore servicing fluid
according to this disclosure. Upon initiating the method II at
start 10, method II includes determining a wellbore servicing fluid
(e.g., a drilling fluid) water salinity at 20 and dosing a known
volume of the wellbore servicing fluid into a container. As noted
hereinabove, the wellbore servicing fluid can be a drilling fluid
(e.g., a drilling mud). The drilling fluid can be a water based mud
(WBM) or an oil based mud (OBM). The water phase salinity of the
wellbore servicing fluid can be determined at step 20 via any
available methods, such as, without limitation, conductivity,
colorimetry, or the like. As noted hereinabove, the known volume of
the wellbore servicing fluid dosed at step 30 can be obtained
subsequent circulation of the wellbore servicing fluid downhole
(e.g., subsequent passage of a drilling fluid into a drill string
in a wellbore, through a drill bit, and back to a surface of the
wellbore via an annulus). For example, the known volume of the
wellbore servicing fluid can be obtained from a flow line or in a
mud pit uphole. As detailed hereinabove with reference to FIG. 1,
the known volume can include a test sample "as is", or solids can
be removed from the known volume of the wellbore servicing fluid
and/or the known volume of the wellbore servicing fluid can be
diluted to provide a test sample. For example, as indicated at step
40, method II can further include adding a known amount of diluent
(e.g., water) to the known volume of wellbore servicing fluid and
optionally mixing to provide the test sample. Step 40 can include,
for example, centrifuging the known volume of wellbore servicing
fluid, taking an amount from the supernatant (e.g., the water phase
of the WSF), and diluting with water (with optional mixing) to
provide the test sample. Method II includes at step 50, adding a
detector compound such as a chromophore dye to the test sample and
mixing. Method II further includes at step 60B, measuring the shale
inhibitor content of the test sample utilizing the colorimetric
method detailed herein. Method II further includes, at step 70,
reporting the data from step 60B to a computer control system. At
step 80B, method II includes, determining (e.g., via the control
system) wellbore servicing fluid (e.g., drilling fluid) treatment
based on the colorimetric results from step 60B and water phase
salinity (WPS) from step 20. Method II includes, at step 90B,
subjecting the wellbore servicing fluid of the wellbore servicing
system to the treatment, for example by adding shale inhibitor(s)
and/or salt(s) to the wellbore servicing fluid system (e.g., to the
mud pit). At step 100, method II includes waiting for a next time
interval to test the wellbore servicing fluid system (e.g., the mud
system). The waiting time at step 100 can depend, for example and
without limitation, on the wellbore servicing fluid system volume
(e.g., the mud system volume) and pump rate. At 110, the method II
includes initiating the method again by returning to start 10.
Steps 10, 20, 30, 40, 50, 70, 100, and 110 can be substantially the
same for method II as for method I of FIG. 1.
ADDITIONAL DISCLOSURE
A first aspect, which is a method of detecting a shale inhibitor
and/or a salt in a wellbore servicing fluid (WSF) comprising: (a)
contacting an aliquot of the WSF with a detector compound to form a
detection solution; wherein the detection solution is characterized
by at least one absorption peak wavelength, for example in the
range of from about 380 nanometers (nm) to about 760 nm; (b)
detecting an absorption intensity for the detection solution at a
wavelength within about .+-.20% of the at least one absorption peak
wavelength; (c) comparing the absorption intensity of the detection
solution at the wavelength within about .+-.20% of the at least one
absorption peak wavelength with a target absorption intensity of
the shale inhibitor and/or the salt to determine the amount of
shale inhibitor and/or salt in the WSF; and (d) comparing the
amount of shale inhibitor and/or salt in the WSF with a target
amount of the shale inhibitor and/or the salt.
A second aspect, which is the method of the first aspect, wherein
the detection solution is characterized by a visible color.
A third aspect, which is the method of the second aspect, wherein
the aliquot of the WSF is further characterized by a visible color,
and wherein the visible color and/or color intensity of the
detection solution is different from the visible color and/or color
intensity of the aliquot of the WSF.
A fourth aspect, which is the method of any one of the first
through the third aspects, wherein (b) detecting an absorption
intensity for the detection solution at a wavelength within about
.+-.20% of the at least one absorption peak wavelength further
comprises subjecting at least a portion of the detection solution
to ultraviolet-visible (UV-VIS) spectroscopy and/or colorimetry to
yield the absorption intensity of the detection solution at the
wavelength within about .+-.20% of the at least one absorption peak
wavelength.
A fifth aspect, which is the method of the fourth aspect, wherein
at least a portion of the detection solution is analyzed in a
portable UV-VIS spectrometer and/or a portable colorimeter.
A sixth aspect, which is the method of any one of the first through
the fifth aspects, wherein (c) comparing the absorption intensity
of the detection solution at the wavelength within about .+-.20% of
the at least one absorption peak wavelength with a target
absorption intensity of the shale inhibitor and/or the salt
comprises optically comparing the color and/or color intensity of
the detection solution with a target color and/or color intensity,
respectively.
A seventh aspect, which is the method of the sixth aspect, wherein
determining the amount of shale inhibitor and/or salt in the WSF
further comprises using a calibration curve that correlates
absorption intensity at the wavelength within about .+-.20% of the
at least one absorption peak wavelength with the amount of the
shale inhibitor and/or the salt, respectively.
An eighth aspect, which is the method of any one of the first
through the seventh aspects, wherein determining the amount of
shale inhibitor and/or salt in the WSF further comprises visually
comparing a visually observed color and/or color intensity of the
detection solution with a reference color chart that correlates
color and/or color intensity, respectively, with the amount of the
shale inhibitor and/or the salt, respectively.
A ninth aspect, which is the method of any one of the first through
the eighth aspects, wherein the amount of shale inhibitor and/or
salt in the WSF varies by less than a threshold amount from the
target amount of the shale inhibitor and/or the salt, respectively,
and wherein at least a portion of the WSF is placed in a wellbore
and/or subterranean formation.
A tenth aspect, which is the method of the ninth aspect, wherein
the WSF is placed in a wellbore and/or subterranean formation prior
to determining the amount of shale inhibitor and/or salt in the
WSF.
An eleventh aspect, which is the method of any one of the first
through the ninth aspects, wherein the WSF is placed in a wellbore
and/or subterranean formation subsequent to determining the amount
of shale inhibitor and/or salt in the WSF.
A twelfth aspect, which is the method of any one of the first
through the eighth aspects, wherein the amount of shale inhibitor
and/or salt in the WSF varies by equal to or greater than a
threshold amount from the target amount of the shale inhibitor
and/or the salt, and wherein the WSF is contacted with an effective
supplemental amount of shale inhibitor, salt, and/or base fluid to
provide for the WSF having the target amount of the shale inhibitor
and/or the salt.
A thirteenth aspect, which is the method of the twelfth aspect
further comprising determining the effective supplemental amount
and preparing the WSF having the target amount of the shale
inhibitor and/or the salt on-the-fly.
A fourteenth aspect, which is the method of any one of the twelfth
and the thirteenth aspects further comprising placing at least a
portion of the WSF having the target amount of the shale and/or the
salt inhibitor in a wellbore and/or subterranean formation.
A fifteenth aspect, which is the method of any one of the first
through the fourteenth aspects, wherein the WSF is recovered from a
wellbore and/or subterranean formation, wherein at least a portion
of the recovered WSF is subjected to a solids removal procedure to
yield a substantially solids-free WSF, and wherein an aliquot of
the substantially solids-free WSF is contacted with a detector
compound to form the detection solution in (a).
A sixteenth aspect, which is the method of the fifteenth aspect,
wherein the solids removal procedure is selected from the group
consisting of filtration, sedimentation, decantation,
centrifugation, screening, chemical dissolution, combinations
thereof
A seventeenth aspect, which is the method of any one of the first
through the sixteenth aspects further comprising heating the
detection solution prior to (b) detecting an absorption intensity
for the detection solution at a wavelength within about .+-.20% of
the at least one absorption peak wavelength.
An eighteenth aspect, which is the method of any one of the first
through the seventeenth aspects, wherein the detector compound
comprises methylene blue, ninhydrin, indane-1,2,3-trione,
hydrantin, quinhydrone, Dragendorff reagent, chloranil,
N-halosuccinimide, N-bromosuccinimide, N-iodosuccinimide, a hydrazo
compound, a diazonium salt, fluorescein, fluorescein halide,
fluorescein chloride, or combinations thereof; additionally or
alternatively, the detector compound may be a chromophore.
A nineteenth aspect, which is the method of any one of the first
through the eighteenth aspects, wherein the shale inhibitor
comprises a salt, a polymer, a charged polymer, a primary amine
functional group, a protonated primary amine functional group, a
secondary amine functional group, a protonated secondary amine
functional group, a tertiary amine functional group, a protonated
tertiary amine functional group, or a combination thereof.
A twentieth aspect, which is the method of any one of the first
through the nineteenth aspects, wherein the WSF comprises a
drilling fluid.
A twenty-first aspect, which is a method of servicing a wellbore in
a subterranean formation comprising (a) preparing a drilling fluid
comprising a base fluid. a shale inhibitor, and/or a salt, wherein
the shale inhibitor and/or the salt are present in the drilling
fluid in a target amount, which is greater than or equal to zero;
(b) circulating the drilling fluid in the wellbore and/or
subterranean formation to yield a circulated drilling fluid; (c)
subjecting at least a portion of the circulated drilling fluid to
solids removal to yield a substantially solids-free circulated
drilling fluid; (d) contacting an aliquot of the solids-free
circulated drilling fluid with a detector compound to form a
detection solution; wherein the detection solution is characterized
by at least one absorption peak wavelength in the range of from
about 380 nanometers (nm) to about 760 nm; (e) detecting an
absorption intensity for the detection solution at a wavelength
within about .+-.20% of the at least one absorption peak
wavelength; (f) comparing the absorption intensity of the detection
solution at the wavelength within about .+-.20% of the at least one
absorption peak wavelength with a target absorption intensity of
the shale inhibitor and/or the salt to determine the amount of
shale inhibitor and/or the salt, respectively, in the circulated
drilling fluid; and (g) comparing the amount of shale inhibitor
and/or salt in the circulated drilling fluid with the target amount
of the shale inhibitor and/or the salt, respectively.
A twenty-second aspect, which is the method of the twenty-first
aspect, wherein the detection solution is characterized by a
visible color.
A twenty-third aspect, which is the method of the twenty-second
aspect, wherein the aliquot of the WSF is further characterized by
a visible color, and wherein the visible color and/or color
intensity of the detection solution is different from the visible
color and/or color intensity of the aliquot of the WSF.
A twenty-fourth aspect, which is the method of any one of the
twenty-first through the twenty-third aspects, wherein the amount
of shale inhibitor and/or salt in the circulated drilling fluid
varies by less than a threshold amount from the target amount of
the shale inhibitor and/or the salt, respectively; and wherein at
least a portion of the circulated drilling fluid is recycled to the
wellbore and/or subterranean formation.
A twenty-fifth aspect, which is the method of any one of the
twenty-first through the twenty-third aspects, wherein the amount
of shale inhibitor and/or salt in the circulated drilling fluid
varies by equal to or greater than a threshold amount from the
target amount of the shale inhibitor and/or the salt, respectively;
wherein the circulated drilling fluid is contacted with an
effective supplemental amount of shale inhibitor, salt, and/or base
fluid to provide for the circulated drilling fluid having the
target amount of the shale inhibitor and/or the salt; and wherein
at least a portion of the circulated drilling fluid is recycled to
the wellbore and/or subterranean formation.
A twenty-sixth aspect, which is the method of the twenty-fifth
aspect further comprising determining the effective supplemental
amount of shale inhibitor, salt, and/or base fluid in real-time and
preparing the circulated drilling fluid having the target amount of
the shale inhibitor and/or the salt, respectively, on-the-fly.
A twenty-seventh aspect, which is a method of servicing a wellbore
in a subterranean formation comprising (a) preparing a drilling
fluid comprising a base fluid, a shale inhibitor, and/or a salt,
wherein the shale inhibitor and/or the salt are present in the
drilling fluid in a target amount; (b) circulating the drilling
fluid in the wellbore and/or subterranean formation to yield a
circulated drilling fluid; (c) subjecting at least a portion of the
circulated drilling fluid to solids removal to yield a
substantially solids-free circulated drilling fluid; (d) contacting
an aliquot of the solids-free circulated drilling fluid with a
detector compound to form a detection solution; wherein the
detection solution is characterized by a first absorption peak
wavelength and optionally by a second absorption peak wavelength;
and wherein the detector compound is optionally contacted with the
aliquot of the solids-free circulated drilling fluid in an amount
of from about 0.01 mmol/liter to about 200 mmol/liter detector
compound, based on the total volume of the detection solution; (e)
detecting an absorption intensity for the detection solution at a
wavelength within about .+-.20% of the first absorption peak
wavelength and optionally the second absorption peak wavelength;
(f) comparing the absorption intensity of the detection solution at
the wavelength within about .+-.20% of the first absorption peak
wavelength and optionally the second absorption peak wavelength
with a target absorption intensity at the wavelength within about
.+-.20% of the first absorption peak wavelength and optionally the
second absorption peak wavelength, respectively, of the shale
inhibitor and/or the salt to determine the amount of shale
inhibitor and/or salt in the circulated drilling fluid; and (g)
comparing the amount of shale inhibitor and/or salt in the
circulated drilling fluid with the target amount of the shale
inhibitor and/or the salt, respectively.
A twenty-eighth aspect, which is the method of the twenty-seventh
aspect, wherein the detection solution is characterized by a
visible color.
A twenty-ninth aspect, which is the method of the twenty-eighth
aspect, wherein the aliquot of the WSF is further characterized by
a visible color, and wherein the visible color and/or color
intensity of the detection solution is different from the visible
color and/or color intensity of the aliquot of the WSF.
A thirtieth aspect, which is the method of any one of the
twenty-seventh through the twenty-ninth aspects, wherein (f)
comparing the absorption intensity of the detection solution at the
wavelength within about .+-.20% of the first absorption peak
wavelength and optionally the second absorption peak wavelength
with a target absorption intensity of the shale inhibitor and/or
the salt comprises optically comparing the color and/or color
intensity of the detection solution with a target color and/or
color intensity, respectively.
A thirty-first aspect, which is the method of any one of the
twenty-seventh through the thirtieth aspects, wherein (f) comparing
the absorption intensity of the detection solution at the
wavelength within about .+-.20% of the first absorption peak
wavelength and optionally the second absorption peak wavelength
with a target absorption intensity of the shale inhibitor and/or
the salt further comprises subjecting at least a portion of the
detection solution to ultraviolet-visible (UV-VIS) spectroscopy
and/or colorimetry in a portable UV-VIS spectrometer and/or a
portable colorimeter, respectively, to yield the absorption
intensity of the detection solution at the wavelength within about
.+-.20% of the first absorption peak wavelength and optionally the
second absorption peak wavelength.
A thirty-second aspect, which is the method of any one of the
twenty-seventh through the thirty-first aspects, wherein the amount
of shale inhibitor and/or salt in the circulated drilling fluid
varies by equal to or greater than a threshold amount from the
target amount of the shale inhibitor and/or the salt, respectively;
wherein the circulated drilling fluid is contacted with an
effective supplemental amount of shale inhibitor, salt, and/or base
fluid to provide for the circulated drilling fluid having the
target amount of the shale inhibitor and/or the salt; and wherein
at least a portion of the circulated drilling fluid is recycled to
the wellbore and/or subterranean formation.
A thirty-third aspect, which is the method of the thirty-second
aspect further comprising determining the effective supplemental
amount of shale inhibitor, salt, and/or base fluid and preparing
the circulated drilling fluid having the target amount of the shale
inhibitor and/or the salt, respectively, in real-time.
While embodiments of the invention have been shown and described,
modifications thereof can be made by one skilled in the art without
departing from the spirit and teachings of the invention. The
embodiments described herein are exemplary only, and are not
intended to be limiting. Many variations and modifications of the
invention disclosed herein are possible and are within the scope of
the invention. Where numerical ranges or limitations are expressly
stated, such express ranges or limitations should be understood to
include iterative ranges or limitations of like magnitude falling
within the expressly stated ranges or limitations (e.g., from about
1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes
0.11, 0.12, 0.13, etc.). For example, whenever a numerical range
with a lower limit, R.sub.L, and an upper limit, R.sub.U, is
disclosed, any number falling within the range is specifically
disclosed. In particular, the following numbers within the range
are specifically disclosed: R=R.sub.L+k*(R.sub.U-R.sub.L), wherein
k is a variable ranging from 1 percent to 100 percent with a 1
percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4
percent, 5 percent, . . . , 50 percent, 51 percent, 52 percent, . .
. , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or
100 percent. Moreover, any numerical range defined by two R numbers
as defined in the above is also specifically disclosed. Use of the
term "optionally" with respect to any element of a claim is
intended to mean that the subject element is required, or
alternatively, is not required. Both alternatives are intended to
be within the scope of the claim. Use of broader terms such as
comprises, includes, having, etc. should be understood to provide
support for narrower terms such as consisting of, consisting
essentially of, comprised substantially of, etc.
For purposes of the disclosure herein, the term "comprising"
includes "consisting" or "consisting essentially of." Further, for
purposes of the disclosure herein, the term "including" includes
"comprising," "consisting," or "consisting essentially of."
Accordingly, the scope of protection is not limited by the
description set out above but is only limited by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. Each and every claim is incorporated into the
specification as an embodiment of the present invention. Thus, the
claims are a further description and are an addition to the
embodiments of the present invention. The discussion of a reference
in the Description of Related Art is not an admission that it is
prior art to the present invention, especially any reference that
may have a publication date after the priority date of this
application. The disclosures of all patents, patent applications,
and publications cited herein are hereby incorporated by reference,
to the extent that they provide exemplary, procedural or other
details supplementary to those set forth herein.
* * * * *